1. Field of the Invention
The present disclosure relates generally to NMR methods of detecting precipitants in a hydrocarbon stream. More particularly, this disclosure relates to the use of NMR spectroscopy or NMR relaxometry for detecting or predicting formation of solids in a hydrocarbon stream.
2. Background of the Invention
Gas hydrates are ice-like structures in which water molecules, under pressure, form structures composed of clathrate hydrate cages which are nano-scale polyhedral cages surrounding gas molecule “guests” such as methane and ethane. Rarely encountered in everyday life, hydrates occur in abundance under sea floor and permafrost environments where (P, T) conditions ensure hydrate stability. Natural gas trapped in these deposits represents a potential source of energy many times known natural gas reserves. Hydrates can form as well in undersea piping and above ground pipelines where they pose a major problem for gas/oil producers.
Hydrate plugs are often formed during oil production, due to the presence of water and light hydrocarbons such as methane at low temperatures and high pressures. Hydrate can be formed by nitrogen, carbon dioxide, hydrogen sulfide, methane, ethane, propane, iso-butane, n-butane, and some branched or cyclic C5-C8 hydrocarbons. When natural gases such as methane come into contact with water at high pressure and low temperature, the formation of gas hydrates can lead to problems with flow assurance, i.e. the assurance of unrestricted flow of fluids through pipelines. Formation of hydrate can plug natural gas pipelines and reduce or inhibit flow. Hydrate plugs can cause serious safety issues as well as problems with deep-water flow assurance in oil and gas flow lines.
To prevent hydrate plugging, chemical hydrate inhibitors are often added into the pipelines. Additionally, thermal insulations can be installed to prevent heat loss so that temperature does not drop to the point where conditions are favorable to hydrate formation. The use of hydrate inhibitors is an imprecise science and is an industry exceeding $500 million dollars annually. Dose rates of hydrate inhibitors and thermal insulation designs are based on the expected pipeline conditions relative to the hydrate phase diagram. Therefore, accurate phase diagrams are essential to safety and economic considerations. Equally important are hydrate formation and dissociation kinetics, key factors in hydrate management. Unfortunately, current models for predicting hydrate phase behavior show considerable discrepancy with experimental data for black oil systems. The differences can be as much as a 5-6 degree temperature change, which will either invoke unnecessary expense or put the operation at great risk. New experimental data is needed to test and tune phase behavior models. However, hydrate phase behavior in black oil, particularly with emulsions, is poorly understood due to the associated experimental difficulties. No kinetic data on gas hydrates in black oil has yet been reported.
Since hydrate cannot be visually observed in black oil, some methods rely on measuring gas pressure and temperature changes in order to predict when conditions are ripe for hydrate formation. One method is to monitor the pressure changes in a closed volume system. In this method, natural gas, black oil, and gas are charged to a high pressure cell. The pressure is monitored as the closed system is ramped in temperature. Because the gases have to transport through the liquid oil and water phases, some means of mechanical stirring is often employed to facilitate the gas mass transfer. Pressure drops dramatically upon hydrate formation because hydrate formation consumes large quantities of gas. After hydrate formation, the temperature is raised to dissociate the hydrate. As hydrate dissociates, gas is evolved and the pressure increases significantly. The transition point that indicates complete hydrate dissociation, (normally where pressure and temperature return to the original P, T curve before hydrate formation), is identified as the hydrate thermodynamic point.
Because gases have to diffuse through the liquid phase for hydrate behavior to create pressure responses, the complication of gas mass transfer is involved and hydrate behavior is only indirectly observed. Due to the slow diffusion of gases in black oil, pressure responses are often delayed which leads to subsequent delay in hydrate formation prediction. It is difficult to determine the correct hydrate onset point since the determination of ripe conditions does not always mean hydrates will immediately form. This pressure monitoring technique encounters difficulties when the oil phase is too viscous, the amount of water is too small, or the gas phase is absent.
Another problem encountered in pressure and temperature change based monitoring systems is the inability to acquire correct hydrate equilibrium points in black oil. In systems which have the ability to form multi-hydrates, such as natural gas and black oil, the thermodynamic point of hydrates occurs at equilibrium when the last hydrate crystal dissociates. Because the dissociation of several small hydrate crystals can be easily missed by simply tracking the gas pressure change, hydrate crystals can remain in black oil even though the pressure change indicates a complete dissociation of hydrate.
Finally, in oil and gas production, occasionally several small hydrates may form individually rather than in large clumps. When this occurs, the accuracy in predicting the amount of hydrate via traditional methods is compromised.
Accordingly, an ongoing need exists for a method to detect and/or predict precipitant formation in a hydrocarbon stream enabling a more efficient and substantially less costly use of precipitation inhibitors.